Wells are generally drilled into the ground to recover natural deposits of hydrocarbons and other desirable materials trapped in geological formations in the Earth's crust. Once a formation of interest is reached in a drilled well, drillers often investigate the formation fluids by taking fluid samples from the formations for analysis. The analysis of a fluid sample provides information about the fluid's contents, density, viscosity, bubble point, and other important characteristics. This vital information is used for field planning decisions and for the optimization of upstream and downstream production facilities. Such fluid sampling often is done early in the life of a well to ensure that this vital information is available for field planning decisions and for developing upstream and down stream production facilities.
Typically, a fluid sample is obtained by lowering a fluid sampling tool into the well and withdrawing a fluid sample from an underground formation. One example of a sampling tool is the Modular Formation Dynamics Tester (MDT), which is a registered trademark of Schlumberger Technology Corporation, the assignee of this invention. Exemplary formation testing tools are disclosed in U.S. Pat. Nos. 4,860,581 and 4,936,139 to Zimmerman et al., which are assigned to the assignee of the present invention.
FIG. 1 shows a formation testing tool 101 designed to withdraw a fluid sample from a formation 114. The tool 101 is suspended in a borehole 110 on a wireline 115, or multiconductor cable, that is spooled from the surface. At the surface, the wireline 115 is typically connected to an electrical control system 118 that monitors and controls the tool 101.
Once at a desired depth, the tool 101 is used to obtain a formation fluid sample. The tool 101 has a probe 120, or fluid admitting means, that is selectively extendable from the tool 101, as well as an anchoring member 121 on the opposite side of the tool 101 that is also selectively extendable. The probe 120 extends from the tool 101 and seals against the borehole wall 112 so that the probe 120 is in fluid communication with the formation 114. A typical tool 101 also includes a pump (not shown). The pump is used to pump formation fluids from the formation into the tool 101. The pump may also be used to pump formation fluids from the tool 101 into the borehole 110.
One of the problems associated with fluid sampling is that the formation fluid is typically contaminated with mud filtrate. Mud filtrate is a fluid component of the drilling mud that seeps into the formation during the drilling process. The mud filtrate invades the formation and contaminates the native formation fluid near the borehole. When a fluid sample is withdrawn from the formation, the sample will initially include a significant portion of mud filtrate. Thus, in the initial stages of sample collection, the fluid sample is not representative of the native formation fluids.
To solve this problem, a fluid sample typically is withdrawn from the formation and pumped into the borehole or into a large waste chamber in the sampling tool until the fluid being withdrawn has been “refined” or “cleaned up.” A “refined” or “cleaned up” sample is one where the concentration of mud filtrate in the fluid sample is acceptably low so that the fluid represents the native formation fluids. At that point, a sample may be collected for later analysis.
Referring to FIG. 1 again, formation fluid is withdrawn from the formation 114 by the probe 120, and the fluid passes through a fluid analyzer 125 before it is pumped out of the tool 101 and into the borehole by a pumping means (not shown). The fluid analyzer 125 analyzes the fluid sample to determine the level of mud filtrate contamination. Once the formation fluid being withdrawn through the probe has cleaned up, a fluid sample may be taken by pumping the fluid sample into one of the sample chambers 122, 123.
One type of fluid analyzer used in a formation testing tool is an optical sensor, which measures the'optical density (“OD”) of the fluid sample at several different wavelengths in the near-infrared (“NIR”) and visible light spectra. The OD is calculated from the transmittance, which is a ratio of the transmitted light to the incident light. The OD typically is calculated as OD=−log10(T), where T is the transmittance. The oil used in an oil-based mud (“OBM”) typically is light in color, thus, as the fluid sample cleans up, the OD at the color channels increases asymptotically to the OD of the darker native formation fluid. For water based mud (“WBM”) the mud filtrate is usually colorless, thus, as the fluid sample cleans up, the OD at the color channels increases asymptotically to the OD of the darker native formation fluid.
Two types of absorption contribute to the OD of a fluid sample: color absorption and molecular vibration absorption. Color absorption occurs when incident light interacts with orbital electrons. Oils may exhibit different colors because they have varying amounts of aromatics, resins, and asphaltenes, each of which absorb light in the visible and NIR spectra. For example, heavy oils have higher concentrations of aromatics, resins, and asphaltenes, which give them dark colors. Light oils and condensate, on the other hand, have lighter, yellowish colors because they have lower concentrations of aromatics, resins, and asphaltenes.
Molecular vibration absorption is the absorption of a particular frequency of light due to resonance of the chemical bonds in a molecule. While color absorption covers the visible and NIR spectrums, molecular vibration absorption occurs only at specific wavelengths for specific materials. For any given molecule, the wavelength at which vibration absorption occurs is related to the molecular structure and the types of chemical bonds in the fluid sample. For example, most oils have molecular vibration absorption peaks near wavelengths of 1,200 nm, 1,400 nm, and 1,700 nm.
Another factor that can affect the measured OD of a fluid sample is known as “scattering.” Scattering is when the incident light is reflected by particles in the fluid sample so that the reflected light does not reach the detector. Typically, scattering occurs independent of the wavelength of the incident light, but there are some circumstances where scattering may depend on the wavelength of light.
Molecular vibration absorption is a function of the concentration of the particular substance, and it is not necessarily affected by the phase of the substance. For example, the methane absorption resonance peak (near 1,670 nm) will have about the same magnitude, regardless of whether the methane is in the gas phase or dissolved in the oil.
FIG. 2 shows the OD of several types of oil, including condensate 202, black oil 204, and tar 206. The OD of these fluids due to color is wavelength dependent and forms a continuous curve over the wavelength spectrum. The OD for the oils shown in FIG. 2 also have molecular vibration absorption peaks 212, 214, 216 at specific wavelengths. Where the OD due to color is a continuous curve over the spectrum, the OD due to molecular vibration absorption occurs only at discrete wavelengths. As shown in FIG. 2, crude oils have molecular vibration absorption peaks at about 1,200 nm (shown at 212), at about 1,400 nm (shown at 214), and at about 1,700 nm (shown at 216).
One type of optical sensor is the Optical Fluid Analyzer (“OFA”), which is a trademark of Schlumberger Corporation, the assignee of the present invention. The OFA measures the OD of the fluid sample at ten different wavelengths in the NIR and visible ranges. When fluid is first withdrawn from a formation, the fluid sample is composed mostly of light colored OBM filtrate or WBM filtrate. As the fluid sample cleans up, the fluid sample will contain more of the darker native formation fluid. The OD of the fluid sample in color channels will change as the fluid cleans up. For example, because the formation fluid is darker in color than a typical OBM filtrate, the OD of the fluid sample at the color channels will increase as the fluid sample is withdrawn. The OD at the color channels will asymptotically approach the OD of the formation fluid.
By taking OD data at multiple times, the OD of the native formation fluid, called the “contamination free” OD, can be mathematically determined by computing the asymptotic value of the measured OD. “Contamination free OD” means the OD of the fluid sample when there is no contamination in the sample, (i.e., the OD of the formation fluid). Once the contamination free OD is predicted, the amount of OBM filtrate contamination in the fluid sample may be determined based on the measured OD and the contamination free OD. Methods for determining the contamination of OBM in a fluid sample are disclosed, for example, in U.S. Pat. No. 5,266,800 to Mullins, which is assigned to the assignee of the present invention.
Another type of optical sensor is called the Live Fluid Analyzer (“LFA”), which is a Trademark of Schlumberger Corporation, the assignee of the present invention. The LFA is different from the OFA because the LFA includes a methane channel at the wavelength of a “methane peak”. Both the LFA and OFA have an oil channel at the wavelength of an “oil peak.” A “methane peak” is a molecular vibration absorption peak of methane, whose wavelength corresponds to the resonance of the CH bond in a methane molecule. One methane molecular vibration absorption peak occurs at a wavelength of about 1,670 nm. The molecular vibration absorption occurs independently of the color of the fluid and independently of whether the methane is in the gas phase or dissolved in the formation fluid. Similarly, an “oil peak” is a molecular vibration absorption peak of oil, whose wavelength corresponds to the resonance of the combination of CH2 and CH3 groups in an oil molecule. The oil peak typically is at a wavelength of about 1,720 nm.
Typically, OBM filtrate contains negligible amounts of methane, so the OD at the methane peak will increase as the fluid sample is withdrawn from the formation. The OD of the methane peak will asymptotically approach the OD at the methane peak of the formation fluid. The percent contamination of the fluid sample may be determined by monitoring the OD in the methane channel and comparing it to the asymptotic value.
Another formation fluid property that may be calculated using a methane channel is the gas oil ratio (“GOR”). The GOR is the ratio of the volume of hydrocarbons in the gaseous phase in the native formation fluids over the volume of liquid hydrocarbons at standard conditions. The GOR is important in the design of the upstream and downstream production facilities. For example, if the GOR is high, the surface facilities must be designed to handle a large amount of gas from the well. One method for calculating the GOR is disclosed in U.S. Pat. No. 6,476,384 to Mullins, et al., incorporated by reference in its entirety, which is assigned to Schlumberger Technology Corporation, the assignee of the present invention.
Another type of optical sensor is called the Condensate and Gas Analyzer (“CGA”), which is a Trademark of Schlumberger Corporation, the assignee of the present invention. A CGA uses optical channels at specific frequencies to get a better estimate of the spectrum of gases and liquids present in a fluid sample. For example, a typical CGA has a channel that corresponds to the resonance peak for molecular vibration absorption in carbon dioxide. A typical CGA is able to determine mass concentrations of methane, non-methane gaseous hydrocarbons, carbon dioxide, and liquid hydrocarbons.
While these analyzers provide convenient methods for monitoring various components in formation fluids and, hence, the extent of the mud filtrate contamination in the formation fluids, they may still be affected by the color of the fluid sample, the amount of water present in the fluid sample, and any particles in the fluid sample that scatter the incident light used to measure the OD. It is desirable to have methods that remove the effects of color, water, and scattering.